1. Technical Field
The present invention relates generally to a process for treating natural gas and other fluid streams, and exemplarily for a liberating process of VOC and BTEX components from a regeneratable solvent fluid stream wherein the solvent fluid stream also contains acid gas components that are to be retained in solution for subsequent and separate removal.
2. Background Art
Most natural gas when initially produced from a well is not xe2x80x9ccleanxe2x80x9d, but is instead laden with associated compounds that may require removal prior to utilization of the natural gas as a fuel gas. Naturally occurring compounds in the natural gas include VOC (volatile organic compounds) and acid gas, all of which may be required to be removed in a gas treatment process. Generally speaking, and especially within the present disclosure, acid gas refers to the constituent components, carbon dioxide and/or hydrogen sulfide, that are often entrained in a produced natural gas flow stream. If a gas flow stream is high in hydrogen sulfide content, it may be classified as xe2x80x9csourxe2x80x9d, regardless of its carbon dioxide content. If a gas stream is high in carbon dioxide, but not necessarily hydrogen sulfide, it is generally referred to as xe2x80x9chigh CO2 gas.xe2x80x9d In common usage, however, and as used herein, xe2x80x9csourxe2x80x9d gas is utilized to describe a gas that is xe2x80x9coff specxe2x80x9d; that is, high in content with respect to either carbon dioxide or hydrogen sulfide. A gas stream is said to be xe2x80x9csweetenedxe2x80x9d by a process that removes the acid gas therefrom.
The primary component of natural gas is methane which typically accounts for about ninety percent of the produced gas. Organic compounds entrained in the gas and that are heavier than ethane are typically considered by regulatory agencies to be VOC. There is also a subset of the VOC""s which are referred to as BTEX and includes benzene, toluene, ethylbenzene and xylene. In terms of environmental impact and regulatory restraints, VOC""s will normally have certain limits placed upon their free release as will BTEX""s, but the limits will be more stringent with respect to the subset, BTEX, of the VOC""s. An example would be the allowance of twenty-five tons per year of total VOC, but only ten tons per year of BTEX in a vent stream.
U.S. Pat. No. 4,548,620 exemplifies a conventional and still utilized process for treating natural gas. Therein, an amine based solvent is used as a stripping agent for acid gas. Because of the type of solvent used for the stripping, VOC is also stripped therefrom and entrained in the solvent. In this system and others of conventional design, the VOC and acid gas components have an affinity for the amine solution and are absorbed by physical and/or chemical reaction thereinto. The solvent is referred to as being xe2x80x9cleanxe2x80x9d when not laden with contaminants and as xe2x80x9crichxe2x80x9d when entrained with contamination.
In a conventional system, after an adequate contacting process has been undergone to expose the sour gas to the amine solvent, the highly pressurized rich absorbent fluid stream of amine is processed to a flash tank where the pressure is reduced from approximately 900 psia to approximately 65 psia. In the example of the ""620 patent, this flash process is conducted at approximately 85 psia. When this occurs, the more volatile absorbed components xe2x80x9cfizxe2x80x9d back out of the amine solution and are liberated therefrom. These released gases can be used as fuel gas or flared off. This portion of the regeneration process for the amine stream removes a portion of the VOC.
As may be best appreciated in the figures of the ""620 patent, the elevational relative position of the flash tank 18 is significantly lower than the feed point of the stripper 22. As a result, the process within the flash tank must be conducted at such a pressure as the indicated 85 psia in order to provide sufficient pressure to conduct the processed liquid amine solution through piping, valves, heat exchangers, filters and to the higher feed point near the top of the stripper. This construction is what is typical, and that which is regularly encountered in present designs and installations. It should also be appreciated that the flash process occurs at approximately 155 degrees Fahrenheit in the flash tank of the ""620 patent. This is also typical of known processing plants.
Because of the pressure constraints that require the flash process to be conducted at pressures on the order of 85 psia as exemplified in the ""620 patent, only a limited amount of VOC can be liberated from the solvent. This temperature and pressure, however, is not appropriate for liberating the acid gas from the solvent stream. In many cases, a substantial amount of the VOC that is entrained in the amine solvent is not removed in these typical flash tank conditions and therefor remains in solution, still absorbed in the solvent that is conducted downstream for further processing. In such conventional designs, the VOC-rich amine solution leaves the flash tank and most of the acid gas components are subsequently removed in a stripper, together with a large portion of the remaining VOC. This amount of VOC often exceeds regulations dealing with environmental pollution and is therefore desired to be eliminated.
There are cases in which the exhaust gas stream from the stripper is high in carbon dioxide, but contains acceptably low amounts of hydrogen sulfide to enable venting or flaring. There still may be, however, amounts of VOC present that are too high for venting and therefore regulations require the effluent stream from the stripper to be burned in a flare to rid it of the environmentally offending VOC content. The problem encountered at this juncture of the process is that this gas stream is not sufficiently flammable to burn under its own combustibility because of the high CO2 content. Therefore, fuel gas must be introduced for the effluent stream in sufficient quantities to permit its being burned in a flare. In practice, the amount of fuel gas required is significant and can add an appreciable cost to the processing of the gas. It is not unusual for this cost to amount to as much as $100,000 per year.
In practice, it is not uncommon for a gas processing plant to be compliant with respect to VOC (as an example less than twenty-five tons per year) but out of compliance with respect to BTEX (as an example, more than ten tons per year) in the stripper""s exhaust gas content. Therefore, it stands to reason that the owners of such gas processing plants are very interested in improving their compliance with respect to VOC and BTEX emissions, and minimizing or eliminating the need for adding as much as $100,000 per year in fuel gas to the process to flare the VOC and high CO2 content stripper exhaust stream. These plants, however, continue to incur such expense without having invented a suitable solution for both the design of new plants and for retro-fitting existing gas processing plants that will reduce or eliminate this high cost of regulatorily compliant operation.
In view of the above described deficiencies associated with the use of known designs for process treatments of natural gas, the present invention has been invented and developed to alleviate these drawbacks and provide further benefits to the user. These enhancements and benefits are described in greater detail hereinbelow with respect to several alternative embodiments of the present invention.
The present invention in its several disclosed embodiments alleviates the drawbacks described above with respect to conventionally designed gas treatment processes and incorporates several additionally beneficial features. In the illustrated embodiment, the present invention interposes a supplementing or performance enhanced VOC removal station in the treatment process. In the supplementing format, the existing VOC removal station (typically in the form of a flash tank) may be supplemented with: (1) a supplementing high temperature flash tank (gas separator) between the original VOC flash tank and the stripper tower; (2) a supplementing low pressure flash tank at that same location; or (3) a supplementing low pressure/high temperature flash tank at that same location, each such supplementing flash tank being includeable for the purpose of removing a predominance of the remaining VOC after the original flash tank and before the stripper. What is important is that the temperature and/or pressure are regulated at this supplementary flash tank so that conditions are appropriately maintained for liberating the VOC from the amine solution flow, but not the acid gas constituents. In this manner, a VOC rich gas exhaust stream is produced from the supplementing flash tank, much like that produced in the original flash tank, that is sufficiently flammable based on its own content to be flared because it is not significantly diluted with incombustible carbon dioxide. In some situations, a small amount of fuel gas may be required to burn the exhausts from the flash tanks, but, the amount of such fuel gas is significantly less than that previously required (exemplarily $100,000 per year) for flaring the liberated gas from the stripper. Still further, this VOC stream may be advantageously utilized as a fuel gas source because of its combustibility.
In the case of new construction gas processing plants or reconstruction of existing plants, similar objectives and performance characteristics may be enjoyed from the substitution of a single flash tank having operational qualities in which the temperature and/or pressure are regulated therein so that conditions are appropriately maintained for liberating VOC thoroughly from the amine solution flow, but not driving off the acid gas constituents.
In the instances where operating pressures in the flash tank are not high enough to conduct the amine solution downstream to the top of the stripper tank, at least two solutions are available. One solution is to provide a supplemental pump for pumping the fluid from the flash tank to the stripper. A second solution is to elevate the position of the flash tank to above the stripper so that the amine solution will be under sufficient pressure upstream of the flash tank to be pressure driven to such an elevation, and from there the solution can flow to the lower stripper under the influence of gravity.
Based on simulations, as much as 80 to 90% of the VOC content can be removed in the two ways described above from the rich amine solution prior to processing through the stripper. In the instance of the supplementing configuration, about 70 percent of any remaining VOC after the original flash tank is readily removed at the supplementary VOC removal station when appropriate temperature and/or pressure conditions are maintained. In many instances, this reduces the VOC load in the rich amine to an amount that can be legally vented from the stripper. In this manner, the need for adding fuel gas to the VOC stream pulled off at the supplementing VOC removal station is either eliminated or significantly reduced resulting in an overall cost reduction for the gas treatment process. If a small amount of additional fuel gas is required, however, it is advantageous to add that fuel gas prior to the amine solution""s processing in the flash tanks thereby enhancing the VOC""s liberation efficiency therein. It is for this reason that such addition of fuel gas is also referred to as stripping gas in the trade.
In the same manner that a gas processing plant must reduce VOC effluent from its vent gas, a sulfur plant, which is often associated with a gas processing plant, advantageously benefits from the reduction or removal of VOC from gas streams treated therein. In the event that significant amounts of hydrogen sulfide are driven off of the amine solution at the stripper, treatment will often be necessary by a sulfur plant. A basic process of a sulfur plant is incineration which effectively treats any VOC that may remain in the exhaust stream being treated. Certain catalysts, however, are utilized in the sulfur plant""s processes that can be fouled by the presence of VOC and can result in the formation of coke and soot that can be poisoning to the catalyst. As a result, there will be situations in which sulfur plants may benefit from the exploitation of the present invention.
Still further, another application for the presently disclosed invention is the treating of liquid streams for acid gas removal. The process is essentially identical, except that instead of treating natural gas in the contactor, the amine is treating liquids such as ethane, propane, or most commonly, mixed natural gas liquids (NGL mix).
In at least one embodiment, the present invention takes the form of a method for removing residual VOC components from a fluid stream used in the removal of acid gas from produced natural gas. Typically, this method will be implemented in a retro-fit environment where a flash tank already exists in a gas treatment plant. The method includes interposing a supplementing VOC removal station after a primary or original VOC removal station in an absorbent fluid stream. The absorbent fluid stream incorporates fluid into which acid gas and VOC have been absorbed from a treated gas stream such as produced natural gas. The primary VOC removal station is configured to remove an initial portion of the absorbed VOC from the absorbent fluid stream. The supplemental VOC removal station is configured to liberate a portion of residual absorbed VOC remaining in the absorbent fluid stream downstream from the primary VOC removal station. Further, the supplemental VOC removal station is configured to avoid liberating absorbed acid gas from the absorbent fluid stream.
The configuration of the supplemental VOC removal station to liberate a sufficient portion of the residual absorbed VOC remaining in the absorbent fluid stream downstream from the primary VOC removal station is calibrated to leave a remaining level of absorbed VOC in the absorbent fluid stream downstream of the supplemental VOC removal station that is legally ventable without further processing.
In one embodiment, proper conditions in the supplemental VOC removal station are established by pressure regulation. In another embodiment, proper conditions in the supplemental VOC removal station are established by temperature regulation. In a preferred embodiment using temperature regulation, a liberating temperature of approximately 190xc2x0 F. is maintained therein.
In an exemplary embodiment, the absorbent fluid stream comprises an amine solution, and preferably an alkanolamine containing solution.
When advantageous, fuel gas may be added to the absorbent fluid stream upstream of the supplemental VOC removal station to assist in the removal of VOC from the absorbent fluid stream at the supplemental VOC removal station.
In at least one embodiment, the liberated portion of the residual absorbed VOC remaining in the absorbent fluid stream downstream from the primary VOC removal station is at least seventy percent.
An additional embodiment of the present invention takes the form of a method for providing a low-cost acid gas treatment plant in which a gaseous effluent mixture of VOC and acid gas are liberated from a scrubbing solution which has features similar to those described above. Still further, another embodiment of the present invention takes the form of a method for reducing operational costs of an existing acid gas treatment plant in which a gaseous effluent mixture of VOC and acid gas liberated from a scrubbing solution require the introduction of fuel gas thereto for disposal burning by retro-fitting an existing sour gas treatment plant as described herein.
The beneficial effects described above apply generally to the exemplary devices and processes disclosed herein of the apparatus and method for exclusively removing VOC from regeneratable solvent in a gas processing system. The specific structures and processes through which these benefits are delivered will be described in detail hereinbelow.